Method for Evaluating Voids in a Subterranean Formation

ABSTRACT

Voids adjacent a wellbore wall and in a region surrounding a wellbore wall can be detected by monitoring gamma rays scattered from the fractures. Gamma rays are strategically directed from a tool disposed within the wellbore and to the wall and/or the region. Some of the gamma rays scatter from the voids and are detected with detectors set a designated axial distance from the gamma ray source. In addition to identifying the presence of the voids, the location and size of the fractures/perforations is also estimated. Time lapsed imaging of the wellbore wall can yield changes in the voids that in turn can affect permeability of the well. Examples of the voids include fractures and/or perforations.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part and claims the benefit ofco-pending U.S. application Ser. No. 13/645,248 filed Oct. 4, 2012,which is a continuation-in-part and claims the benefit of co-pendingU.S. application Ser. No. 13/332,543 filed Dec. 21, 2011, which is acontinuation-in-part of and claims the benefit of U.S. application Ser.No. 12/496,163 filed Jul. 1, 2009, the full disclosures of which arehereby incorporated by reference herein for all purposes.

BACKGROUND

1. Field of Invention

The invention relates generally to assessing fractures in a subterraneanwellbore. More specifically, the present invention relates to a deviceand method that uses a radiation source in conjunction with a radiationdetector for a time lapsed evaluation of fractures in a formationintersected by the wellbore.

2. Description of Prior Art

Subterranean wellbores used for producing hydrocarbons typically arelined with a casing string that is cemented to the formation intersectedby the wellbore. The casing and the surrounding formation are thenperforated to provide fluid communication between the formation andinterior of the casing. Fluid produced from the well flows through theperforations, to within the casing, and to the surface within productiontubing that is inserted inside the inner casing string.

Some hydrocarbon bearing formations can have low permeability due to thepresence of shale, or very tight formation rock (such as in limestoneformations); which in turn can limit hydrocarbon production. However,natural or man-made fractures in these formations can increase formationpermeability thereby increasing hydrocarbon production. Identifying thelocation and size of these fractures are of considerable importance indetermining which part of the borehole to perforate and produce. Often,a layer of shale is on top of a formation that contains hydrocarbons.Generally, it is more stable to drill in the layer of shale than thehydrocarbon bearing formation. In these situations, a wellbore isdrilled through the shale with the hopes of intersecting a fracture inthe shale that extends into the reservoir having the hydrocarbons, asfractures increase permeability of a subterranean formation.

Wellbores often include portions that are lined with a gravel pack,which is made up of particles of a designated size that are retainedbetween a perforated tubular in the wellbore and the wellbore wall. Thegravel pack, which is typically one or more of sand, gravel, orproppant, provides support for unconsolidated zones in the subterraneanformation surrounding the wellbore. Without gravel pack, unrestrainedparticulate matter in the formation could become dislodged as producedfluid flows from the formation, which could possibly damage tubulars,valves, and other fluid production hardware. The gravel pack is alsosometimes forced into the subterranean fractures to not only preventunwanted particulate matter in the formation from entering the producedfluid, but also to support the fractures and prevent them fromcollapsing. In spite of injecting proppants into the fractures, they canstill compress over time due to applied formation stresses. Drillingprocedures have changed in response to environmental concerns so thatfluids and cuttings are injected into hydraulically generated fracturesof depleted reservoirs. Although the cuttings may be ground in speciallymodified centrifugal pumps, a risk remains that the ground cuttings canplug or otherwise degrade the fractures in the subterranean formation.

As with re-injection wells, conventional wells in producing fields canchange their productivity because fracture permeability can changeduring oil and gas production. For example, erosion or breakdown ofproppant materials (for example, resin-coated proppant sands oropen-channel proppant deterioration) typically results in loss ofproduction (see E. d'Huteau, Oilfield Review Vol 23, No. 3, Autumn2011).

SUMMARY OF THE INVENTION

Disclosed herein is a method of imaging a wellbore which includesdirecting radiation from a source to a formation surrounding thewellbore, detecting radiation scattered from the formation, estimating arate and energy of the detected radiation, and estimating informationabout a change of a void in the formation based on the rate and energyof the detected radiation. The void can be a fracture or a perforation.The steps of directing radiation, detecting scattered radiation, andestimating a rate and energy can take place over time in order toperform time lapsed imaging. The source can be a gamma ray source andwhich is directed in a substantially conical pattern from the source andwherein the energy of the detected radiation is dependent upon an angleof scatter of the radiation. Optionally, the information about a changeof the void can be a change in thickness of the void, a change ofpermeability in the void, a change in flowability through the void, or achange of density of material in the void. The method can optionallyfurther include estimating a location of the void. The void can be afracture that intersects a wall of the wellbore, or a a perforation thatintersects a wall of the wellbore. In an example, the wellbore is aninjection well, or can be a production well.

Also disclosed is a method of imaging a wellbore which includesproviding a logging instrument having a radiation source and a radiationdetector; disposing the logging instrument into the wellbore and withincasing that lines the wellbore, directing radiation from the source to aformation surrounding the wellbore and along a path, so that at leastsome of the radiation scatters in a direction back from the formationtowards the radiation detector, detecting radiation scattered from theformation with the radiation detector, and identifying a change in avoid in the formation based on a change of rate of the radiationdetected. The void can be an opening in the formation which is aperforation or a fracture. The steps of the method are repeated overtime so that the change of rate of the radiation detected comprises atime lapsed measurement. The radiation can be directed fully from theouter circumference of the logging instrument so that the radiationscatters from an entire circumference of a wall of the wellbore. Themethod can be repeated while moving the logging instrument to differentdepths in the wellbore.

An example of a method of imaging a wellbore is disclosed herein thatincludes directing radiation from a source to a formation surroundingthe wellbore, detecting radiation scattered from the formation,estimating a rate and energy of the detected radiation, repeating thesteps of directing radiation, detecting scattered radiation, andestimating a rate and energy of the detected radiation at a later timeto perform a time lapsed measurement, and estimating information about achange of a void in the formation based on the time lapsed measurement.Estimating information about a change of a void in the formation can bebased on a rate and energy of the detected radiation. Optionally, alocation of the void can be estimated. The void can be a space in theformation such as a fracture or a perforation.

BRIEF DESCRIPTION OF DRAWINGS

Some of the features and benefits of the present invention having beenstated, others will become apparent as the description proceeds whentaken in conjunction with the accompanying drawings, in which:

FIG. 1 a schematic of an example embodiment of a downhole imaging toolhaving a radiation source and detectors disposed in a wellbore inaccordance with the present invention.

FIG. 2 is a perspective view of one embodiment of the tool of FIG. 1 inaccordance with the present invention.

FIGS. 3A and 3B are sectional views of an example embodiment of the toolof FIG. 2 in accordance with the present invention.

FIG. 4 is a side sectional view of an example method of an imaging toolin a wellbore that emits gamma rays to a surrounding formation inaccordance with the present invention.

FIG. 5 is a side sectional view of an example of perforating thewellbore of FIG. 4 and in accordance with an embodiment of the presentinvention.

FIG. 6 is a side sectional view of an example method of time lapsedimaging of the wellbore with perforations of FIG. 4 and in accordancewith the present invention.

While the invention will be described in connection with the preferredembodiments, it will be understood that it is not intended to limit theinvention to that embodiment. On the contrary, it is intended to coverall alternatives, modifications, and equivalents, as may be includedwithin the spirit and scope of the invention as defined by the appendedclaims.

DETAILED DESCRIPTION OF INVENTION

The method and system of the present disclosure will now be describedmore fully hereinafter with reference to the accompanying drawings inwhich embodiments are shown. The method and system of the presentdisclosure may be in many different forms and should not be construed aslimited to the illustrated embodiments set forth herein; rather, theseembodiments are provided so that this disclosure will be thorough andcomplete, and will fully convey its scope to those skilled in the art.Like numbers refer to like elements throughout. In an embodiment, usageof the term “about” includes +/−5% of the cited magnitude. In anembodiment, usage of the term “substantially” includes +/−5% of thecited magnitude.

It is to be further understood that the scope of the present disclosureis not limited to the exact details of construction, operation, exactmaterials, or embodiments shown and described, as modifications andequivalents will be apparent to one skilled in the art. In the drawingsand specification, there have been disclosed illustrative embodimentsand, although specific terms are employed, they are used in a genericand descriptive sense only and not for the purpose of limitation.

Referring now to FIG. 1 a downhole imaging tool 100 is shown positionedin a section of casing or inner steel housing 110 of a wellbore. It isrecognized that a tool housing 130, such as that surrounding the regionof the source and detector array, may be constructed of any light metalwherein the term, “light metal,” as used herein, refers to any metalhaving an atomic number less than 23. Downhole imaging tool 100 includesat a minimum a housing or pipe 130 carrying a radiation source 120 andplurality of detectors 140. In one example embodiment, gamma radiationsource 120 is centrally located in housing 130. Optionally, detectors140 are symmetrically spaced apart azimuthally at a constant radius,within housing 130. Radiation source 120 emits radiation, in this case,gamma rays 124 into formation 150 surrounding the casing 110. Cement 151is between the casing 110 and formation 150.

The formation 150 of FIG. 1 includes fractures 153, 155 that could befluid-filled or not. For example, fracture 153 contains completionfluids or production fluids, whereas fracture 155 is partially or fullysand filled. Of course, those skilled in the art, with the benefit ofthis disclosure, will appreciate that these are for illustrativepurposes only and that fractures 153, 155 could take any shape and anyposition.

In the example of FIG. 1, gamma rays 124 propagating into formation 150are Compton scattered with a loss of some energy back towards detectors140 located within downhole imaging tool 100. The reduced-energy gammarays 126 are detected by detectors 140. The count-rate intensity ofCompton scattered. gamma rays 126 depends on, among other factors, thesize of the fracture and the density of the material inside thefracture. Hence, higher count rates represent higher density material inthe formation, whereas lower count-rates represent lower density as aresult of fewer gamma rays being back-scattered towards the detectors.

In an example, radiation source 120 includes a cesium, or some otherradiation source, or combinations thereof. Because the detectors arelocated close to the source, energy detected from scattered gamma raysoriginates only from a short distance into the formation immediatelyadjacent the casing. For these same reasons, in one example detectors140 are positioned in housing 130 proximate to radiation source 120. Inone example embodiment, radiation source 120 and detectors 140 arewithin about 3 to about 3.5 inches apart along the length of tool 100.

Shielding 156 may be applied around radiation source 120 to collimate orotherwise limit the emission of radiation from radiation source 120 to arestricted longitudinal segment of formation 150. In an embodiment, suchshielding is a heavy metal shield, such as sintered-tungsten, whichcollimates the pathway for the emitted gamma rays into the fractures.Likewise, as described in more detail below, similar shielding may beused around each detector to limit the detector viewing aperture to onlythose gamma rays that are primarily singly-scattered back to thedetector from a restricted azimuthal section of the formation.

Further, the energy levels of the emitted gamma rays 124 may be selectedto assess fracture characteristics at varying depths or distances fromdownhole imaging tool 100. As one example, the radiation from a gammaray source, such as a ¹³³Ba source, may be used to emit several energylevels. Alternatively, a gamma ray radiation source with a single energygamma ray, such as ¹³⁷Cs, may be used.

To produce an accurately oriented map of the fracture locations, theazimuthal angle of the logging tool relative to the high side of theborehole is determined. This orientation can be determined using anyorientation device known in the art. Orientation devices may contain oneor more attitude sensors used to determine orientation of the loggingtool with respect to a reference vector. Examples of suitableorientation devices include, but are not limited to, those orientationdevices produced by MicroTesla of Houston, Tex. Each set of gamma raymeasurements may be associated with such an orientation so that a 2Dprofile map of the formation can be accurately generated in terms of theactual azimuthal location of the fracture.

FIG. 2 illustrates a perspective view of one embodiment of a gravel packimaging tool. As shown, downhole imaging tool 200 includes a housing 230which carries radiation source 220, source collimator 225, and aplurality of radiation detectors 240 in an array. The array of detectors240 may be positioned at a fixed distance from radiation source 220. Incertain embodiments, detector arrays may be positioned at differingdistances from radiation source 220. Additionally, detector arrays oneither side of radiation source 220 are also envisioned in certainembodiments. Electronics 260 may also be located in housing 230 orwherever convenient.

Radiation source 220 may be one or more radiation sources, which mayinclude any suitable low-energy gamma ray source capable of emittinggamma ray radiation from about 250 keV to about 700 keV. Gamma raysources suitable for use with embodiments of the present invention mayinclude any suitable radioactive isotope including, but not limited to,radioactive isotopes of barium, cesium, a LINAC, high energy X-rays(e.g. about 200+ keV), or any combination thereof. Radiation fromradiation source 220 may be continuous, intermittent, or pulsed.

In one example embodiment shown in FIG. 2, a radiation source 220 iscentrally located in housing 230. In the illustrated embodiment, source220 is positioned along the axis of housing 230.

Gamma-Ray collimator 225, which is optional in certain embodiments, maybe-configured adjacent to the source 220 in order to directionallyconstrain radiation from the radiation source 220 to an azimuthalradiation segment of the formation. For example, collimator 225 mayinclude fins or walls 226, 228 adjacent source 220 to direct gamma raypropagation. By directing, focusing, or otherwise orienting theradiation from radiation source 220, radiation may be guided to a morespecific region of the formation. Additionally, the radiation energy maybe selected, by choosing different isotopic sources, so as to providesome lithological or spatial depth discrimination.

In the illustrated embodiment, collimator 225 constrains radiation fromsource 220. In this embodiment, collimator 225 is also conically shapedas at 228, in the direction of detectors 240 to collimate the gamma raysfrom source 220. Of course, those skilled in the art will appreciatethat collimator 225 may be configured in any geometry suitable fordirecting, focusing, guiding, or otherwise orienting radiation fromradiation source 220 to a more specific region of the formation.

In one non-limiting example, the radiation transmitted from source 220into a formation (such as formation 150 of FIG. 1) is Compton scatteredback from the formation to tool 200 where the back-scattered radiationmay be measured by radiation detectors 240. Radiation detectors 240 canbe any plurality of sensors suitable for detecting radiation, includinggamma ray detectors. In the illustrated embodiment, four detectors aredepicted, although any number of detectors can be utilized. In anotherexample embodiment, three detectors or six detectors are utilized; whereoptionally, each detector is disposed to “view” a different segment ofthe formation. Employing multiple detectors, the tool can image theentire circumference of the casing 110 in separately identifiablesegments. The resolution of the image of the overall circumference candepend on the number of detectors, the energy of the gamma rays and thedegree of shielding provided around each detector.

In certain embodiments, gamma ray detectors may include a scintillatorcrystal that emits light proportional to the energy deposited in thecrystal by each gamma ray. A photomultiplier tube may be coupled to thecrystal to convert the light from the scintillation crystal tomeasurable electron current or voltage pulse, which is then used toquantify the energy of each detected gamma ray. In other words, thegamma rays' energies are quantified, counted, and used to estimate thedensity of material in a fracture. Photomultiplier tubes may be replacedwith high-temperature charge-coupled devices (CCD) or micro-channelphoto-amplifiers. Examples of suitable scintillator crystals that may beused include, but are not limited to, NaI(Tl) crystals, BGO, andLanthanum-bromide, or any combination thereof. In this way, count-ratesmay be measured from returned radiation, in this case, returned gammarays. The intensity of the Compton scattered gamma rays depends on,among other factors, the density of the formation material. Hence, lowerdensity represents gaps in the formation, such as may be caused by theformation being fractured and lower count-rates represent lower densityas a result of fewer gamma rays being back-scattered towards thedetectors.

Still referring to FIG. 2, in an example embodiment detectors 240 aremounted inside a housing at a radius smaller than the radius of housing230 inset from the surface of housing 230. Likewise, while they need notbe evenly spaced, in the illustrated embodiment, detectors 240 areevenly spaced on the selected radius. Although the illustrated exampleshows four detectors 240 spaced apart 90 degrees from one another, thoseskilled in the art will appreciate that any number of multiple detectorscan be utilized in the invention. Further, while the embodimentillustrates all of the detectors 240 positioned at the same distancefrom source 220, they need not be evenly spaced. Thus, for example, onedetector (or a multi-detector array) might be spaced apart 12centimeters from the source, while another detector (or a detectorarray) is spaced apart 20 centimeters from the source or any otherdistance within the tool.

Similarly, in another embodiment, detectors 240 can be positioned bothabove and below source 220. In such a case, collimator 225 would beappropriately shaped to guide gamma rays in the direction of the desireddetectors. In such embodiments with multiple detectors disposed on bothsides of the radiation source, additional shielding may be providedbetween the collimators to prevent radiation scattering (i.e.cross-contamination of the radiation) from different segments of theformation.

Each detector 240 may be mounted so as be shielded from the otherdetectors 240. While any type of shielding configuration may be utilizedfor the detectors 240, in the illustrated embodiment, collimator 248 isprovided with a plurality of openings or slots 245 spaced apart aroundthe perimeter of collimator 248. Although openings 245 could have anyshape, such as round, oval, square or any other shape, in one exampleembodiment openings 245 are shaped as elongated slots and will bereferred to as such herein.

A detector 240 is mounted in each slot 245, so as to encase detector 240in the shield. The width and depth of the slot 245 can be adjusted asdesired to achieve the desired azimuthal range. In certain embodimentsthe length of slots 245 can be as long as the sensitive region of thegamma-ray detector (e.g. the crystal height). It will be appreciatedthat since a detector is disposed within the slot, the detector is noton the surface of the collimator where it might otherwise detect gammarays from a larger azimuthal range. In an example embodiment, slot 245is 360/(number of detectors) degrees wide and the detector face to innerdiameter of the pressure housing is a few millimeters deep (e.g. fromabout 2 to about 5 mm). However, tighter collimation is possible.Optionally, the azimuthal range of each slot is limited to 360/(numberof detectors) degrees. In this way, the view of each radiation detector240 may be more focused on a particular region of the formation.Additionally, such shielding eliminates or at least mitigates radiationscattered from one detector to another detector. As can be seen, eachdetector is separated from one another by radiation absorbent material.By eliminating detector-to-detector radiation scattering, more preciseazimuthal readings are achieved.

While source collimator 225 is shown as a single, integrally formed bodyand conical surface 228, it need not be and could be formed of separatestructural components, such as a source collimator combined with adetector collimator 248, so long as the shielding as described herein isachieved.

In the illustrated embodiment, the region of housing 230 around theopening in source collimator and detectors 240 may be fabricated ofberyllium, aluminum, titanium, or other low atomic number metal ormaterial, the purpose of which is to allow more of the gamma rays toenter detectors 240. This design is especially important for lowerenergy gamma rays, which are preferentially absorbed by any dense metalin the pressure housing.

Alternatively, or in addition to detector shielding or detectorcollimator 248, an anti-coincidence algorithm may be implemented inelectronics 260 to compensate for detector-to-detector radiationscattering. In this way, a processor can mitigate the effects ofmultiply-detected gamma rays via an anti-coincidence algorithm. Incertain embodiments, electronics 260, 262, and 264 are located abovedetectors 240 or below source 220.

Electronics 260 may include processor 262, memory 263, and power supply264 for supplying power to gravel pack imaging tool 200. Power supply264 may be a battery or may receive power from an external source suchas a wireline (not shown). Processor 262 is adapted to receive measureddata from radiation detectors 240. The measured data, which in certainembodiments includes count rates, may then be stored in memory 263 orfurther processed before being stored in memory 263. Processor 262 mayalso control the gain of the photomultiplier or other device forconverting scintillations into electrical pulses. Electronics 260 may belocated below source 220 and above detectors 240 or removed therefrom.

In one embodiment, the tool further includes an accelerometer, a 3 axisinclinometer or attitude sensor to unambiguously determine the positionof an azimuthal segment. In certain embodiments, a compass device may beincorporated to further determine the orientation of the tool.

Fracture detection tool 200 may be constructed out of any materialsuitable for the downhole environment to which it is expected to beexposed, taking into account in particular, the expected temperatures,pressures, forces, and chemicals to which the tool will be exposed. Incertain embodiments, suitable materials of construction for sourcecollimator 225 and detector collimator 248 include, but are not limitedto, sintered tungsten (known as heavy-met), lead, dense and very-highatomic number (Z) materials, or a combination thereof.

Further, while a 1 11/16 inch diameter configuration tool is illustratedin FIG. 1, the tool 100 can be sized as desired for a particularapplication. Those skilled in the art will appreciate that a largerdiameter tool would allow more detectors and shielding to providefurther segmentation of the view of the formation.

This tool may be deployed to detect fractures and to estimate theirsize. A person of ordinary skill in the art with the benefit of thisdisclosure will appreciate how to relate the log results of count ratesand inferred densities of formation material to the structure of theformation and to reason from the results to the condition of theproperties of the detected fractures.

As a further illustration of an exemplary geometry of the embodimentillustrated in FIG. 2, FIGS. 3A and 3B show cross-sectional views ofanother embodiment of the tool disposed in base pipe or productiontubing 330, which is further disposed in casing 310. An annulus 350 isdefined between the casing 310 and the tubing 330, where FIG. 3A shows across-section taken from the X-Y plane, which is perpendicular to thetool longitudinal axis, and where FIG. 3B shows a cross-section takenfrom the X-Z plane, along the tool longitudinal axis. As shown in theillustrated embodiment, upper and lower source collimators 328, 329 areeach conical shaped in the X-Z plane or Y-Z plane. More specifically,upper collimator 328 has a surface that defines an emission angle θ₁with respect to the tool longitudinal axis A_(X), and lower collimator329 has a surface that defines an emission angle θ₂ with respect to axisA_(X). Detector 340 is shown in FIG. 3A in openings or slots 345,whereas radiation source 320 is shown depicted in FIG. 3B. As shown inFIG. 3A, detector collimators 348 are fan-shaped in the X-Y plane andrectangular in the X-Z or Y-Z planes. In certain embodiments, upper andlower conical source collimators 328, 329 reduce multiple scatteringevents in unwanted regions surrounding the tool and creatingun-necessary background. More specifically, strategic placement andconfiguration of the conical upper and lower source collimators 328, 329causes radiation from the source to be directed from the source 320 andsingle scatter from the wellbore wall (or gravel pack) to the detectors340. The shape of the upper and lower source collimators 328, 329 andselective positioning of the detectors 340 from the source 320, vastlyincreases the number of counts detected by the detectors 340 ofradiation that have single scattered (rather than undergone multiplescatters) so that resolution of the gathered data can be increased,thereby providing data that better represents the downhole formation. Inan example, the angles θ₁,θ₂ are chosen so that the tool 10 can be putin different sized wellbores; where the spacing between the source 320and detectors 340 is adjusted to ensure single scattering is detected inthe varying diameter wellbores.

In addition to the energy levels of the radiation source, other factorsthat may be adjusted to discriminate segmented views of the formationinclude, but are not limited to the angle of the collimators and thesource to detector spacing. Examples of suitable values of the emissionangles θ₁, θ₂ range from about 15° to about 85°, and all values between15° to about 85°, and wherein the lower value of the range of emissionangles θ₁, θ₂ can be 15° to about 85° (and all values in between), andwherein the upper value of the range of emission angles θ₁, θ₂ can be15° to about 85° (and all values in between). Examples of suitablesource to detector spacing include, but are not limited to, from about 1inch to about 12 inches, and all values between 1 to 12 inches.

Moreover, it is recognized that the downhole tool is capable ofmeasuring count rates while being lowered or raised in the wellbore. Incertain embodiments, the downhole tool may perform measurements whilethe tool is stationary in the wellbore. Exemplary raising and loweringrates include displacement rates of up to about 1800 feet/hour.

FIG. 4 illustrates in a partial side sectional view, an example of animaging tool 400 inserted within a tubular 402. Embodiments existwherein the tool 400 can be the same or substantially the same as thetools 100, 200 respectively of FIGS. 1, 2, and 3 and described above. Inthe example of FIG. 4, the tubular 402 is inserted into a wellbore 404that is shown intersecting a subterranean formation 406. Casing 408 isoptionally provided in the wellbore 404 for lining the sidewalls of thewellbore 404. Thus in this example, the tubular 402 is productiontubing. Alternate examples of use exist wherein the tool 400 is insertedwithin casing 408 having no production tubing within. The tool 400 isdeployed in the wellbore 404 on a line 410, where the line 410 can be awireline, slickline, cable, or coiled tubing. The line 410 is showninserted through a wellhead assembly 412 that is mounted on surfaceabove an opening to the wellbore 404. Fluid 413 is illustrated in thetubular 402 and surrounding the space between the tool 400 and walls ofthe tubular 402.

Further illustrated in the embodiment of FIG. 4 are fractures 414 in theformation 406 surrounding the wellbore 404. In an example, fractures 414define a discontinuity in the formation 406 that may occur whereadjacent portions of rock or other subterranean strata shear from oneanother. In the example of FIG. 4, lengths of the fractures 414 canrange from less than a foot, to in excess of many feet. In an example,the presence of the fractures 414 can be detected with the tool 400. Inan example, included with the embodiment of the tool 400 of FIG. 4 is aradiation source 416, which can be substantially the same as sources220, 320 respectively of FIGS. 2 and 3B and described above. Further inthe example of FIG. 4, a sensor 418 is included with the tool 400,wherein the sensor 418 includes detectors 140, 240 respectively of FIGS.1 and 3 and discussed above. Radiation emitted from the source 416 cantravel along a path represented by arrows A, which initially divergesfrom the axis A_(X). Some of the radiation undergoes scattering and isredirected to converge with the axis A_(X) at a location axially awayfrom the source 416. As shown, the redirected radiation contacts sensor418 where a count and associated energy of the radiation is detected.

Still referring to the example embodiment of FIG. 4, the radiation isdirected in a conical pattern away from the source 416 and generallyabout a line intersecting the source 416 and sensor 418. As such, theradiation Compton scatters from the fluid 413 in the tubular 402, anarea proximate the sidewall of the tubular 402, and the formation 406.At least some of the radiation scatters from materials in the fractures414. It should be pointed out that paths the radiation follows from thesource 416 to the sensor 418 are not limited to the select number ofarrows A that are illustrated for clarity.

As is known, the energy of the radiation detected by the sensor 418 isaffected by the Compton single-scatter angle of the radiation (i.e. theangle of the directional change of the radiation). Generally, the energydecreases with increasing scattering angles; thus the radiation flowingfrom the source 416 to the sensor 418 which undergoes only minimalscattering will have a greater detected energy than the radiation singlescattered over a large angle from adjacent the tubular 402 the formation406. The radiation single scattered from adjacent the tubular 402 willhave a greater detected energy than the radiation single scattered fromthe formation 406 because the average angles are shallower. In anexample, radiation counts detected by sensor 418 are binned based on anenergy level of each count. It is within the capabilities of thoseskilled in the art to identify the substances from which the radiationscatters based on the counts and corresponding energy of the createdspectrum. Moreover, those skilled in the art are capable of identifyinga spatial location of the identified substances.

In an example, source 416 and sensor 418 are set apart a designateddistance so that the gamma rays from the source 416 scatter from aregion 420 at the wall of the wellbore 408. Optionally, the range of theregion 420 from which the gamma rays from the source 416 scatter extendsradially outward past the wall of the wellbore 408 and to within theformation 406. Region 420 can be an annular space circumscribing thewellbore 404 and having a radial thickness ranging from a few inches toseveral feet. Detecting the actual number of Compton scattered gammarays per unit time provides an indication of the density of materialfrom which the gamma rays have scattered. Moreover, material filling afracture 414 generally has a density different from the surroundingformation 406. Thus, a change in rate of gamma rays detected by sensor418 can indicate that a fracture 414 is at the wall of the wellbore 404or in the region 420.

In one non-limiting example of use of the tool 400 of FIG. 4, the tool400 is raised within the wellbore 404 on wireline 410 while gamma raysemitted from the source 416 Compton scatter from the wall of thewellbore 404 and/or from within the region 420 around the wellbore 404.As discussed above, the location of scatter can depend on the relativelocations of the source 416 and sensor 418. Also noted above, a fracture414 at the wall of the wellbore 404, or in the region 420, can beidentified by a change in the rate of gamma rays detected by sensor 418.Moreover, by correlating the depth of the tool 400 in the wellbore 404with any changes in gamma ray detection rate, a height or width of afracture 414 can be estimated. Advantages of using the method and tool400 described herein include that fractures are identifiable with gammaray detection that are outside the size range detectable by knownacoustic means.

An additional advantage of utilizing Compton scattering of gamma rays toidentify fractures 414 in the formation 406 surrounding the wellbore404, is that their vertical and azimuthal locations can be identifiedwith precision, as well as their size. As illustrated in FIG. 5,strategically placed perforations 422 can be formed in the formation 406based on precise spatial information of the fractures 414 derived fromuse of the tool 400 described above. An example embodiment of aperforating string 424 is shown disposed in the wellbore 404 for formingthe perforations 422. The string 424 includes a series of perforatingguns 426 with shaped charges 428. In the example of FIG. 5, the shapedcharges 428 are disposed at a depth in the wellbore 404 and oriented sothat when they are detonated, an ensuing metal jet (not shown) createsperforations 422 across the wall of the wellbore 404 and into theformation 406 to intersect with the fractures 414. In the example ofFIG. 5, the tubular 402 lining the wellbore 404 is wellbore casing, andcement 430 is disposed in the annular space between the casing and wallof the wellbore 404. Thus the perforation 422 also extends through thecasing and the cement 430. The intersection between the perforations 422and fractures 414 create fluid communication between fractures 414 andthe wellbore 404. Embodiments exist wherein the formation 406 is a shaleformation adjacent a formation (not shown) having a hydrocarbon bearingreservoir; and wherein a fracture 414 extends into the adjacentformation and into communication with hydrocarbons therein. Thusintersecting fracture 414 that extends into the adjacent formation witha perforation 422 necessarily communicates the wellbore 404 with thehydrocarbon bearing reservoir.

Referring now to FIG. 6, an example of the imaging tool 400 isillustrated disposed in wellbore 404 and imaging the formation 406around the wellbore 404; where the steps of imaging the formation 406can be the same or similar to that described above and illustrated inFIG. 4. Further as described above, the tool 400 is moved within thewellbore 404 during imaging so that data from the formation 406 can begathered at multiple wellbore depths. Analyzing the gathered data canprovide information about the material within perforations 422 and/orfractures 414 in the formation 406. In an example, the information aboutthe material includes the density of the material. Changes in thedensity of the material in the perforations 422 and fractures 414, whichcan be caused by the buildup of sand plugging or reactive changes (scaleor dissolution), or fracture re-closure, can be estimated with timelapsed imaging in the wellbore 404 with the tool 400. In an embodiment,time lapsed imaging includes performing a baseline measurement made atan initial time with the tool 400, and then conducting subsequentmeasurements with the tool 400; any changes between imaged data obtainedat different times can be used to estimate density changes.

Examples exist wherein the initial time of imaging takes place prior tointroducing proppant into the wellbore 404, or after introducingproppant into the wellbore 404. As permeability of the perforations 422and fractures 414 can be affected by the density of the material in theperforations 422 and fractures 414, monitoring changes in density ofthis material can therefore yield information about changes inpermeability of the perforations 422 and fractures 414. Accordingly,imaging the formation 406 with the tool 400 can be used to determinewhich the perforations 422 and fractures 414 have undergonedeterioration by using a time-lapse differential profile loggingtechnique. Information about deterioration, or lack of deterioration,can enable well operators to plan remedial operations. In addition tomonitoring density changes of material in the perforations 422 andfractures 414, any changes in size of the perforations 422 and fractures414 can be monitored. Size changes of the perforations 422 and fractures414 can include one or more of thickness, width, length, andcombinations thereof. In an example, the perforations 422 and fractures414 define voids in the formation 406.

One advantage of understanding the dynamics offracture-evolution/development (i.e. injection, storage, and dissipativebleed off) during repeated cycles of cuttings re-injection in criticalto maintain the integrity of any well, including a disposal well.Optionally, a differential log profile is generated that depicts thedifference between a base-line logging measurement done early in thelife of the well, and subsequent measurements made after the well hasbeen used for some time. Differences in the fracture density profilescan indicate changes in the fractures caused by re-injection processes.

The present invention described herein, therefore, is well adapted tocarry out the objects and attain the ends and advantages mentioned, aswell as others inherent therein. While a presently preferred embodimentof the invention has been given for purposes of disclosure, numerouschanges exist in the details of procedures for accomplishing the desiredresults. These and other similar modifications will readily suggestthemselves to those skilled in the art, and are intended to beencompassed within the spirit of the present invention disclosed hereinand the scope of the appended claims.

What is claimed is:
 1. A method of imaging a wellbore comprising: a.directing radiation from a source to a formation surrounding thewellbore; b. detecting radiation scattered from the formation; c.estimating a rate and energy of the detected radiation; and d.estimating information about a change of a void in the formation basedon the rate and energy of the detected radiation.
 2. The method of claim1, wherein the void is selected from the group consisting of a fractureand a perforation.
 3. The method of claim 1, wherein steps (a)-(c)include time lapsed imaging.
 4. The method of claim 1, wherein thesource comprises a gamma ray source and which is directed in asubstantially conical pattern from the source and wherein the energy ofthe detected radiation is dependent upon an angle of scatter of theradiation.
 5. The method of claim 1, wherein the information about achange of the void is selected from the group consisting of a change inthickness of the void, a change of permeability in the void, a change inflowability through the void, and a change of density of material in thevoid.
 6. The method of claim 1, further comprising estimating a locationof the void.
 7. The method of claim 1, wherein the void comprises afracture that intersects a wall of the wellbore.
 8. The method of claim1, wherein the void comprises a perforation that intersects a wall ofthe wellbore.
 9. The method of claim 1, wherein the wellbore comprises awell selected from the group consisting of an injection well and aproduction well.
 10. A method of imaging a wellbore comprising: a.providing a logging instrument having a radiation source and a radiationdetector; b. disposing the logging instrument into the wellbore andwithin casing that lines the wellbore; c. directing radiation from thesource to a formation surrounding the wellbore and along a path, so thatat least some of the radiation scatters in a direction back from theformation towards the radiation detector, d. detecting radiationscattered from the formation with the radiation detector; and e.identifying a change in a void in the formation based on a change ofrate of the radiation detected.
 11. The method of claim 10, wherein thevoid comprises an opening in the formation selected from the groupconsisting of a perforation and a fracture.
 12. The method of claim 10,wherein steps (a)-(d) are repeated over time so that the change of rateof the radiation detected comprises a time lapsed measurement.
 13. Themethod of claim 10, wherein the radiation is directed fully in afan-shaped beam from the outer circumference of the logging instrumentso that the radiation can scatter from an entire circumference of a wallof the wellbore.
 14. The method of claim 10, further comprisingrepeating steps (b)-(e) while moving the logging instrument to differentdepths in the wellbore.
 15. A method of imaging a wellbore comprising:a. directing radiation from a source to a formation surrounding thewellbore; b. detecting radiation scattered from the formation; c.estimating a rate and energy of the detected radiation; d. repeatingsteps (a)-(c) at a later time to perform a time lapsed measurement; ande. estimating information about a change of a void in the formationbased on the time lapsed measurement.
 16. The method of claim 15,wherein step (e) is based on a rate and energy of the detectedradiation.
 17. The method of claim 15, further comprising estimating alocation of the void.
 18. The method of claim 15, wherein the voidcomprises a space in the formation selected from the group consisting ofa fracture and a perforation.